5‐1

CHAPTER 5

COSTS, BENEFITS, ECONOMIC AND ENERGY IMPACTS

5.1 Synopsis

This chapter reports the compliance cost, economic, and energy impact analysis

performed for the EGU GHG NSPS. EPA used IPM, developed by ICF Consulting, in this analysis.

IPM is a dynamic linear programming model that can be used to examine air pollution control

policies throughout the United States for the entire power system. EPA used the IPM model to

forecast likely future electricity market conditions with and without the proposed rule.

BecauseEven in a baseline scenario without the proposed rule, the only capacity

additions projected during the analysis period (through 2020) are compliant with the

requirements of this rule (e.g. coal boilers with CCS funded in part through federal subsidies

and combined cycle natural gas). This conclusion also holds for several sensitivity analyses EPA

performed.  As a result, under a wide range of future electricity market conditions,, this

proposed EGU GHG NSPS is not expected to change GHG emissions for newly constructed

EGUs, nor and is it anticipated to impose notable negligible costs, economic impacts, or energy

impacts on the EGU sector or society.  An additional illustrative analysis, presented at the end

of this chapter, indicates that even in the unlikely event that electricity market conditions

change enough to support additional new coal, the proposed EGU GHG NSPS would provide net

benefits., and concluded based on sensitivity analyses that the price of natural gas would have

to increase to approximately $10/mmBtu for coal boilers without CCS to become competitive

with combined cycle natural gas units which is projected to be very unlikely.1EPA performed

sensitivity analyses that also did not forecast new coal in 2020.  

5.2 Background

Over the last decade, EPA has conducted extensive analyses of regulatory actions

impacting the power sector.  These efforts support the Agency’s understanding of key policy

variables and provide the framework for how the Agency estimates the costs and benefits

associated with its actions.  Current forecasts for the mix of new, and utilization of existing,

generating capacity are a key input into informing the design of EPA’s proposal.  Given excess

capacity within the existing fleet and relatively low forecasts of electricity demand growth,

there is limited new capacity, of any type, expected to be constructed over the next decade.  A

small number of new coal‐fired power plants have been built in recent years; however, EPA

does not forecast the construction of any new unplanned coal‐fired additions over the time

                                                      

1 This chapter presents all costs in 2007$.
5‐2

horizon of this analysis (through the year 2020). For more detailed discussion of this forecast,

see section 5.5.

Under current and foreseeable future market conditions affecting new capacity

additions, gas‐fired There are two main reasons why EPA expects no unplanned coal‐fired

power plants will be constructed over the time horizon considered for this analysis.  First, the

current economic situation has dampened electricity demand, and thus there is less need for

new generating capacity during the analysis period.  Second, generating technologies can

produce electricity for new plants using natural gas produce electricity at a lower levelized cost

than other coal‐fired generating technologies, and therefore utilities are expected to rely

heavily on combustion turbines and combined cycle plants using natural gas when they do need

to expand capacity during the time horizon considered for this analysis. This circumstance is

different than that of a few years ago because cCurrent and projectedforecast natural gas

prices are considerably lower than the levels seenprices observed over the past decade, largely

due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up

new shale gas resources and . This is a result of new drilling techniques that have substantially

increased the supply of economically recoverable natural gas. potentially available to the

marketplace. According to EIA

Shale gas refers to natural gas that is trapped within shale formations. Shales are

fine‐grained sedimentary rocks that can be rich sources of petroleum and natural

gas. Over the past decade, the combination of horizontal drilling and hydraulic

fracturing has allowed access to large volumes of shale gas that were previously

uneconomical to produce. The production of natural gas from shale formations

has rejuvenated the natural gas industry in the United States.

The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early

Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of

technically recoverable natural gas resources as of January 1, 2010. Natural gas from

proven and unproven shale resources accounts for 542 Tcf of this resource estimate.

Many shale formations, especially the Marcellus, are so large that only small portions of

the entire formations have been intensively production‐tested. Consequently, the

estimate of technically recoverable resources is highly uncertain, and is regularly

updated as more information is gained through drilling and production. At the 2010 rate

of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to

supply over 90 years of use. Although the estimate of the shale gas resource base is

lower than in the prior edition of the Outlook, shale gas production estimates increased
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between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued

drilling in shale plays with high concentrations of natural gas liquids and crude oil, which

have a higher value in energy equivalent terms than dry natural gas.2

Based on these market conditions, and detailed analysis and modeling conducted by

EPA, on average the levelized cost of generation from a new natural gas power plant is

expected to be lower on average than the levelized cost of generation from a new coal‐fired

power plant.3,4  This trend has already been observed recently, as natural gas‐fired capacity has

been was the technology of choice for power generation over the last few years (see Figure 5‐

1).

                                                      

2 For more information, see: http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#prospectshale;

http://www.eia.gov/energy_in_brief/about_shale_gas.cfm 3 See Table 5‐3, which reports the lLevelized cCost of nNew gGeneration in the Annual Energy Outlook (AEO) 2011.,

http://205.254.135.24/oiaf/aeo/electricity_generation.html   4 Note that EPA’s analysis, which is consistent with this expectation, is based on sophisticated IPM modeling, and is

not based on simplified LCOE assumptions.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Capacity (MW)

Other

Gas(CC and CT)

Renewable/Hydro

Nuclear

Coal
5‐4

Figure 5‐1.  Historical U.S. Power Plant Capacity Additions, by Technology

Source: National Electric Energy Data System (NEEDS) v4.10_PTox

Note: Renewables include geothermal, biomass, solar, and wind energy technologies.  A considerable amount of

renewables were built in 2009 and 2010, and these are reflected in EPA modeling applications but not necessarily

in NEEDS.  

Numerous energy sector modeling efforts, including recent projections from both EIA

and EPA, have provided results that are consistent with these findings. The Annual Energy

Outlook (AEO) for 2011 shows a very modest amount of CCS‐equipped new coal‐fired power

coming online past 2012, however since these plants are CCS‐equipped in response to Federal

incentives, theythat would be in compliance with this proposal.5  EIA includes some additional

new coal with CCS in its baseline (2 GW), an assumption which EPA has adopted in IPM.  The

new CCS is in response to existing Federal incentives for the technology (the Emergency

Economic Stabilization Act of 2008 and the American Reinvestment and Recovery Act of 2009).  

According to the AEO 2011, the majority of new generating capacity is forecast to be either

natural gas‐fired or renewable, with some lesser amounts of nuclear power.  The AEO 2011 is

based on existing policy and regulations, such as state Renewable Portfolio Standard programs

and Federal tax credits for renewables.6  The DOE concluded, bBased on EIA analysis, DOE

concluded, that “the low capital expense, technical maturity, and dispatchability of natural gas

generation are likely to dominate investment decisions under current policies and projected

prices."7  The economics favoring new NGCC builds additions instead of conventional coal are

robust under a range of sensitivity cases examined in the AEO.  Unplanned additions of coal by

2020 increase are also not forecast in sensitivity cases that separately examine higher economic

growth, lowerer coal prices, lower capital costs for fossil capacitycosts, no risk premium for

greenhouse gas emissions liability from conventional coalconcern regarding future GHG policy,

slower oil and gas technology deployment, lower shale gas recovery per play, and lower shale

gas recovery per well.  In addition, the early release of EIA’s AEO 2012 Early Release (AEO 2012

ER)currently available does not forecast new unplanned coal capacity without CCS through

2020over the period analyzed.  Furthermore, it projects an increase over AEO 2011 in the price

of coal relative to natural gas, strengthening the conclusion that natural gas‐fired generating

technologies are is likely to be the fossil fuel of choice during the analysis period.  The AEO

2012 ER also has lower electric demand projections than those used in IPM, reflecting an

                                                      

5 AEO 2011 has a small amount of planned coal capacity that is under construction and expected to come online in

the next year.  This capacity represents certain units that likely fit the definition of transitional sources under

this proposal.  It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in response to

Federal incentives. 6 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm

7 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at

http://energy.gov/sites/prod/files/QTR_report.pdf.
5‐5

extended economic recovery and increasing energy efficiency in end‐use appliances,8 which

would result in the need for less new capacity in general.

EPA uses IPM to support its understanding of the economic and emissions impacts of air

regulations on the power sector.  IPM forecasts show patterns of future power plant

deployment that are similar to those presented in AEO 2011, and also forecasts no construction

of new conventional coal‐fired power plants under the base case.9  

A number of major utilities have made public announcements consistent with these

modeling results.10

EPA has used IPM extensively over the past two decades in order to analyze options for

reducing power sector emissions.  The model has been used by the Agency to support

regulatory initiatives as well as legislative proposals designed to address air emissions for the

power sector.  All of the IPM scenarios conducted for this rulemaking are available at EPA’s

website and in the public docket.11

The baseline information in this RIA includes the recently finalized Mercury and Air

Toxics Standards (MATS) and Cross State Air Pollution Rule (CSAPR)  In addition to MATS and

CSAPR, the baseline takes into account emissions reductions associated with the

implementation of all finalized federal rules, state rules and statutes, and other binding,

enforceable commitments that are applicable to the power industry and which govern the

installation and operation of pollution controls during the timeframe covered in the analysis.

As noted above, IPM has been used for evaluating the economic and emission impacts

of environmental policies for over two decades.  The economic modeling presented in this

chapter has been developed specifically for analysis of the power sector.  Thus, the model has

been designed to reflect the industry as accurately as possible.  EPA uses the best available

information from utilities, industry experts, gas and coal market experts, financial institutions,

and government statistics as the basis for the detailed power sector modeling in IPM.  More

                                                      

8 AEO 2012 Early Release Overview 9 http://www.epa.gov/airmarkets/progsregs/epa‐ipm/BaseCasev410.html#documentation   10 For example: “We have no other coal‐fueled generation planned at this time... When we do need new capacity,

it is highly likely that we will look to natural gas plants instead of coal, especially if natural gas prices remain as

low as projected.” AEP January 1, 2011, Washington Post; “If you actually look at the economics today, you

would be burning gas, not coal,” Jack Fusco, Calpine, 12/1/2010, Marketplace;  “Coal’s most ardent defenders

are in no hurry to build new ones in this environment.” John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas

prices, gas‐fired generation kind of snowplows everything else” Lew Hay, NextEra, 11/1/2010, Dow Jones. 11 http://www.epa.gov/airmarkt/progsregs/epa‐ipm/index.html
5‐6

detail on IPM can be found in the model documentation, which provides additional information

on the assumptions discussed here as well as all other assumptions and inputs to the model.

5.3 External Review of EPA Applications of IPM

EPA has used IPM extensively over the past two decades to analyze options for reducing

power‐sector emissions.  The model has been used by the Agency to support regulatory

initiatives as well as legislative proposals designed to address air emissions for the power

sector.  All of the IPM scenarios conducted for this rulemaking are available at EPA’s website

and in the public docket.12

The model undergoes periodic formal peer review, which includes separate expert

panels for both the model itself and EPA’s key modeling input assumptions.  For example, over

the past ten years several separate panels of independent experts have been convened to

review IPM’s coal supply and transportation assumptions, natural gas assumptions, and model

formulation.

The rulemaking process also provides opportunity for expert review and comment by a

variety of stakeholders, including owners and operators of the electricity sector that is

represented by the model, public interest groups, and other developers of U.S. electricity sector

models.  The feedback that the Agency receives provides a highly detailed check for key input

assumptions, model representation, and modeling results.

The Agency has used IPM in several recent regulatory contexts.  The model has been

used to support the Agency’s analytics for the Clean Air Interstate Rule, CSAPR, MATS, and over

a dozen legislative analytical efforts to forecast the costs, emission changes, and power sector

impacts of various policies to reduce power sector emissions.  As part of the rulemaking

process, EPA is required to respond to every significant comment submitted.   

The model has also been used by states (e.g., for Regional Greenhouse Gas Initiative ,

the Western Regional Air Partnership, Ozone Transport Assessment Group ), other Federal and

State agencies, environmental groups, and industry, all of whom subject the model to their own

review procedures.

More specifically, the model has received extensive review by energy and

environmental modeling experts over the past two decades.  States have used the model

extensively to inform issues related to ozone in the northeastern portion of the U.S.  This

                                                      

12 http://www.epa.gov/airmarkt/progsregs/epa‐ipm/index.html
5‐7

groundbreaking work set the stage for the NOx SIP call, which has helped reduce summer NOx

emissions and the formation of ozone in densely populated areas in the northeast.  In the late

1990’s, the Science Advisory Board reviewed IPM as part of the CAA Amendments Section 812

prospective studies that are periodically conducted.  The model has also undergone

considerable interagency scrutiny as part of a series of legislative analyses over the past

decade.  These analyses explored a variety of approaches to controlling emissions from the

power sector, and the results were presented to Congress in a comparative manner in order to

evaluate the merits of policy proposals.   The model was also used to support the Agency’s

power sector analyses of legislative climate proposals in 2005, continuing through 2010.   In

addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM

as a key element in the state implementation plan (SIP) process for the National Ambient Air

Quality Standards.  The Agency has also used the model in a number of comparative modeling

exercises sponsored by Stanford University’s Energy Modeling Forum over the past 15 years.

5.4 IPM is a Detailed Bottom‐Up Granular Model

EPA typically presentsapplies IPM outputs in aggregate, in order to consider support

analysis reflecting nationwide impacts of environmental a policiesy, which can also be

considered at a.  Some additional regional level of detail is presented, where appropriate to the

functional organization of the power section.  Although the Agency typically focuses on the

broader system effects when assessing the economic impacts of a particular policy, EPA’s

application of IPM includes a detailed and sophisticated regional representation of key power

sector variables.  For example, the model includes 32 power regions with detailed

representation of the inter‐regional transmission system and reflects the regional aspects of

natural gas and coal markets.  When considering which new units are most cost effective to

build and operate, the model considers the relative economics of various technologies based on

their unique capital costs, operation and maintenance (O&M) costs, fuel costs and emission

profiles.  The capital costs for new units are regionalized through the application of regional

adjustment factors that capture regional differences in labor, material, and construction costs.

These regional cost differentiation factors are based on assumptions used in the EIA’s AEO.

As part of the model’s assessment of the relative economic value of building a new

power plant, the model incorporates a detailed representation of the fossil‐fuel supply system

that supports fuel price projections, a key component of new power plant economics.  The

model includes an endogenous representation of the North American natural gas supply system

through a natural gas module that reflects a full supply/demand equilibrium of the North

American gas market.  This module consists of 114 supply, demand, and storage nodes and 14
5‐8

liquefied natural gas regasification facility locations that are tied together by a series of linkages

(i.e., pipelines) that represent the North American natural gas transmission and distribution

network.

IPM also endogenously models the coal supply and demand system throughout the

continental U.S., and reflects non‐power sector demand and imports/exports.  IPM reflects 84

coal supply curves, 12 coal sulfur grades, and the coal transport network, which consists of

1,230 linkages representing rail, barge, and truck and conveyer linkages.  The coal supply curves

in IPM, which are publicly available, were developed during a thorough bottom‐up, mine‐by‐

mine based approach that depict the coal choices and associated supply costs that power

plants will face over the modeling time horizon.  The IPM documentation outlines the methods

and data used to quantify the economically recoverable coal reserves, characterize their cost,

and build the 84 coal supply curves that are implemented in EPA modeling applications.  The

coal curves used by EPA were developed in consultation with Wood Mackenzie, one of the

leading energy consulting firms and specialists in coal supply.  These curves have been

independently reviewed by industry experts and have been made available for public review on

several occasions over the past two years during the rulemaking process for CSAPR and MATS.   

5.5   Base Case and Sensitivity Analysis of Future Generating Capacity

5.5.1 Base Case Analysis

EPA began its analysis of the economic impacts of the proposed NSPS by conducting a

base case analysis of future generating capacity. This base case incorporates the proposed final

MATS and the proposed final Transport Rule (finalized as CSAPR).13  In addition to MATS and

CSAPR, the baseline takes into account emissions reductions associated with the

implementation of all finalized federal rules, state rules and statutes, and other binding,

enforceable commitments that are applicable to the power industry and which govern the

installation and operation of pollution controls during the timeframe covered in the analysis.

EPA’s IPM modeling for this rule relies on EIA’s Annual Energy Outlook for 2010’s electric

demand forecast for the US and employs a set of EPA assumptions regarding fuel supplies, the

performance and cost of electric generation technologies, pollution controls, and numerous

other parameters.

                                                      

13 http://www.epa.gov/airquality/powerplanttoxics and http://www.epa.gov/airtransport.  
5‐9

The IPM base case projection is based on an electricity demand growth assumption of

0.8 percent annually on average, similar to EIA’s Annual Energy Outlook for 2010, and slightly

higher than the 0.7 percent annual average growth in the AEO 2012 ER. includes a 1 percent

growth in electricity demand, similar to EIA’s Annual Energy Outlook for 2010, which serves as

the basis for IPM’s electric demand projection. Total electricity demand is projected to be

4,104 billion kWh by 2015.  Table 5‐2 shows current electricity generation alongside EPA’s

projection for 2020 using IPM.  This new demand will be fulfilled by existing generating capacity

that is currently not being fully utilized, and new renewable and gas‐fired generating capacity

(see Table 5‐1).  The change in coal represents only retirements of existing plants and no new

unplanned coal builds.  These projections are the result of least‐cost dispatching using IPM, and

reflect the most cost‐effective dispatch and investment option, given a variety of variables and

constraints.  Although most new generating capacity will be renewable and natural gas‐fired,

U.S. electricity demand will continue to be met by a diverse mix of electricity generation

sources (see Table 5‐2).   In addition, coal is projected to continue to provide the largest share

of America’s electricity.14  By 2020, EPA forecasts roughly 27 GW of new renewable capacity, 2

GW of coal with CCS, and 10 GW of new natural gas‐fired capacity.  Although 2 GW of coal with

CCS is included in the base case in response to incentives under existing law, overall coal

capacity is forecast to decline in response to current economics, along with some retirements

due to other air regulations (CSAPR and MATS).  Relative to current levels, EPA anticipates that

the existing coal fleet will increase generation while gas‐fired sources will not change

significantly by 2020.  This dynamic largely emanates from somewhat atypical supply and

demand trends experienced in energy markets over the past few years, where overall electricity

demand has been soft, natural gas prices have dropped considerably, and coal prices have

risen.

Table 5‐1.  Total Generation Capacity in 2010 and Projected by 2020 (GW)

   2010 2020

Pulverized Coal   3167 299304

Natural Gas Combined Cycle 201199 212

                                                      

14 Coal‐fired generation is projected to increase above 2009 actual levels. 2020 natural gas‐fired generation is

projected to be lower than 2010, due in large part to the smaller relative difference in delivered natural gas and

coal prices in different areas of the country projected to occur in 2020 than occurred in 2010.  While the

projected narrowing of this gas price and coal price differential may increase dispatch (generation) from

existing coal units, it is insufficient to shift the economic decision to favor new conventional coal‐fired capacity,

which requires consideration of capital costs in addition to generation costs.  The same trend is seen in AEO

2011 projections.
5‐10

Combustion Turbine 138135 143

Oil/Gas Steam 115111 90

Non‐Hydro Renewables 31 73

Hydro 99 99

Nuclear 102 106

Other 5 74

Total 1,009998 1,0291,030

Notes: The sum of the table values in each column may not match the total figure due to rounding.

Source: 2010 data from EPA's NEEDS v.4.10 PTR.  2020 projections from Integrated Planning Model run by EPA.

Note: “Non‐Hydro Renewables” include biomass, geothermal, solar, and wind electric generation capacity.  The capacity of a

generating unit that is co‐firing gas in a coal boiler is split in this table between “pulverized coal” and “Oil/Gas Steam”

proportionally by fuel use.

Table 5‐2.  2010 U.S. Electricity Net Generation and EPA Base Case Projections for 2020

(Billion kWh)

   Historical Projected

2010 2020

Coal 1,828 1,976

Oil 35 0.1269

Natural Gas 901 873869

Nuclear 807 841840

Hydroelectric 258 287286

Non‐hydro Renewables 139 288289

Other 4 45

Total 3,972 4,3059

Notes: The sum of the table values in each column may not match the total figure due to rounding.

Source: 2010 data from EIA Electric Power Annual 2010, Table 2.1; 2020 projection from IPM run by EPA, 2011.

5.5.2 Sensitivity Analyses

Forecasts suggesting that new coal is unlikely to be built by 2020 have been shown to be

robust under a range of alternative assumptions that influence the industry’s decisions to build

new power plants.  For example, EIA typically supplements the AEO with a series of distinct

scenarios that explore specific issues and examine a future state of the world that deviates

from the core central parameter estimates that underlie the AEO reference case.  Even under

alternative scenarios where assumptions might improve the relative economic value of building

new coal‐fired power plants, the AEO 2011 does not project new coal capacity being built

through 2025, beyond the coal capacity already planned outside of the modeling.  shows no

new (unplanned) coal builds through 2025.  Relevant scenarios include higher economic growth

forecast, lower cost of coal supply, lower capital costs of fossil fuel‐fired energy technologies,
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and less optimistic natural gas supply.15  Although new coal capacity is built in some of these

scenarios after 2025, CAA sSection 111(b) requires that this standard be reviewed every eight

years, thus this regulatory requirement will likely be reviewed and potentially revised after the

2020 timeframe, which serves as the primary focus of this analysis.  Therefore, while the fairly

robust expectation is that no new unplanned coal capacity will be built within the time horizon

of this analysis, there remains a very small probability that new coal capacity might be

constructed absent this regulation. See Section 5.12 for a discussion of how EPA would account

for the social cost of different generation technologies in the unlikely event that a coal unit

would be constructed in the absence of this rule. Given this unlikely circumstance, this rule

could impose some degree of social cost and accrue some degree of social benefit.  However,

EPA has not quantified the costs or benefits associated with this hypothetical and difficult‐to‐

quantify outcome.  These scenarios lead to the fairly robust conclusion that the economics of

new electricity generation are such that there is a very low probability that new unplanned coal

capacity would be built in the absence of this regulation.

In addition to studying the alternative scenarios analyzed by EIA, EPA also conducted

three additional sensitivity analyses using IPM: a low shale gas recovery scenario, a high

electricity demand scenario, and a combination of the two.16  . These scenarios included

alternative assumptions for natural gas supply and future electricity demand, similar in design

to the alternative scenarios analyzed by EIA.  For natural gas,The lower shale recovery scenario

was assumed, whereby that 50 percent less natural gas is recovered from each shale play

relative to the base case(effectively lowering shale reserves by 50 percent, similar to the AEO

2011 low shale gas recovery scenario).  The high electricity demand scenarioFor electricity

growth, demand was assumed that electricity demand growsto grow at an annual average rate

of 1.1 percent, similar to EIA’s high economic growth scenario for AEO 2010 (compared to

about 0.8 percent in the EPA baseline, which is similar to the reference case in AEO 2010).  EPA

ran three separate sensitivities in IPM using the aforementioned assumptions: a base case with

higher electric demand, a base case with lower shale recovery, and a base case with both

assumptions.  Although EPA and EIA do not typically combine scenarios (as EPA did with the

natural gas and demand sensitivity in this analysis), this scenario was performed to

demonstrate that even when considering the occurrence of two independent and multiple

                                                      

15 Conversely, modeling in support of the AEO 2011 show that new natural gas combined cycle capacity is expected

to be higher in 2020 in the low fossil cost and high economic growth scenarios relative to the reference case.    16 Although EPA and EIA do not typically combine scenarios (as EPA did with the natural gas and demand

sensitivity in this analysis), this scenario was performed to demonstrate that even when considering the

occurrence of two independent and highly unlikely assumptions that influence new power plant additions, new

unplanned coal is not expected to be built through 2020.  
5‐12

highly unlikely assumptionsevents that influence new power plant additions, new unplanned

coal is not expected to be built inthrough 2020.  Figure 5‐2 and 5‐3 illustrate electricity demand

and natural gas price in these sensitivity analyses.  Note that the EPA structured the sensitivity

analyses such that natural gas prices and electricity demand growth are both considerably

higher than the comparable AEO 2011 scenarios.17These scenarios show considerably higher

natural gas prices and higher electricity demand growth than any of the comparable AEO 2011

scenarios as well.18  

                                                      

17 EPA’s baseline electricity demand forecast used in IPM v4.10 is based on the demand forecast in AEO 2010.  AEO

2010 electricity demand forecast for the year 2020 is roughly 3.5% higher than the 2020 forecast in AEO 2011.  

EPA’s sensitivity with higher electricity demand growth (using the AEO 2010) uses an electricity demand for

2020 that is 6.5% higher than the reference case AEO 2011 demand for 2020, and 3.4% higher than the demand

in the AEO 2011 high economic growth scenario.  The EPA sensitivity with higher electric demand represents a

very conservative view of electricity demand in 2020 (meaning that its electricity demand projection is

considerably higher than the most recent reference case forecast, therefore representing a future in which new

coal‐fired capacity would be of correspondingly higher economic value to build relative to the reference case

forecast conditions). 18 EPA’s baseline electricity demand forecast used in IPM v4.10 is based on the demand forecast in AEO 2010.  AEO

2010 electricity demand forecast for the year 2020 is roughly 3.5% higher than the 2020 forecast in AEO 2011.  

EPA’s sensitivity with higher electricity demand growth (using the AEO 2010) uses an electricity demand for

2020 that is 6.5% higher than the reference case AEO 2011 demand for 2020, and 3.4% higher than the demand

in the AEO 2011 high economic growth scenario.  The EPA sensitivity with higher electric demand represents a

very conservative view of electricity demand in 2020 (meaning that its electricity demand projection is

considerably higher than the most recent reference case forecast, therefore representing a future in which new

coal‐fired capacity would be of correspondingly higher economic value to build relative to the reference case

forecast conditions).
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Figure 5‐2.  Projected Levels of Electricity Demand in 2020, EPA and EIA

4,305

4,475

4,300

4,190

4,318

3,000

3,200

3,400

3,600

3,800

4,000

4,200

4,400

4,600

EPA ‐ Base Case EPA ‐ High Demand AEO 2010 AEO 2011 AEO 2011 ‐ High

Econ. Growth

TWh
5‐14

Figure 5‐3.  Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Power Sector)

None of these analyzed scenarios resulted in new conventional coal‐fired capacity being

built in 2020 (see Figure 5‐4)  beyond 2 GW of coal with CCS, which is built in response to the

financial incentives for CCS included in the Emergency Economic Stabilization Act of 2008 and

American Recovery and Reinvestment Act of 2009, which authorized and/or appropriated

funding to DOE for CCS deployment.  In the short‐term, most new capacity is projected as a mix

of wind and natural gas in response to the competitive marketplace for fuels and other energy

policies (such as tax credits and state renewable portfolio standards).  .  These scenarios show

similar results as EIA, and serve to further confirm the high likelihood that no new coal capacity

is likely to be built by 2020 in baseline forecasts.

Table 5‐3.  Projected New Capacity in 2020

EPA‐

Base

Case

EPA‐

High

Demand

EPA‐Low

Shale

Recovery

EPA‐High

Demand +

Low Shale

Recovery

4.99

5.51

7.33

7.96

5.74

4.97 5.07

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

EPA ‐ Base Case EPA ‐ High

Demand

EPA ‐ Low Shale

Recovery

EPA ‐ High

Demand + Low

Shale Recovery

EIA ‐ Low Shale

Recovery (AEO

2010)

EIA Reference

Case ‐ AEO 2011

Average Price

(2011, EIA)

Delivered Price, Power Sector ($2007/mmBtu)
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Coal +CCS 2.0 2.0 2.0 2.0

Natural Gas Combined Cycle 7.0 22.7 7.3 24.8

Combustion Turbine 3.0 3.2 2.4 2.4

Oil/Gas Steam 0.0 1.0 2.0 3.0

Non‐Hydro Renewables 26.9 27.6 27.3 31.5

Hydro 0.0 0.0 0.0 0.0

Nuclear 0.0 0.0 0.0 0.0

Other 0.0 0.0 0.0 0.0

Total 38.9 55.5 39.0 60.7

5.6   Analysis of Applicability of Proposed EGU GHG NSPS to Projected New Generating

Capacity

As the second step in the analysis, EPA analyzed the applicability of the NSPS to new

generating capacity anticipated to be built through 2020, and whether the requirements would

require the regulated community to take actions different from those projected in the base

case.

The proposed EGU GHG NSPS discusses potential requirements for new unitsfour types

of units or actions: newly constructed units, reconstructed units, modified units, and

transitional units.  Analysis performed by EPA, along with information from other sources,

suggests that the standards as specified in this proposed rule are not likely to result in notable

negligible emission changes, other quantified benefits, energy impacts, monetized benefits,

costs, or economic impacts by 2020.  This is because analyses performed both by EPA and EIA,

as well as statements and actions of a number of major utilities, demonstrate that generation

technologies other than coal (mostly natural gas and renewable sources) are likely to be the

technologies of choice for new sources due to current and projected market conditions.19

5.6.1   New Units    

This proposal requires that all new fossil‐fuel fired units of greater than 25 megawatt or

greater capacity be able to meet an emission rate standard of 1,000 lbs CO2/MWh on a gross

basis.  It also proposes an alternative standard that would allow new units to meet the 1,000 lbs

                                                      

19 EPA does not anticipate any oil or gas steam boilers to be constructed, either.  Although these types of units

would be subject to this rule, they have not been a technology of choice for the sector in recent years and are

generally smaller (less than the 25 MW applicability threshold included as part of this rule).  In addition, the

operating economics also do not favor this technology, similar to the dynamic with conventional new coal‐fired

capacity.
5‐16

CO2/MWh standard using a 30 year averaging period.  These standards could be met either by

natural gas combined cycle generation or coal‐fired generation using CCS.  

Of the new generating capacity projected to be constructed by 2020, only the fossil‐fuel‐

fired boilers would be affected by the proposed EGU GHG NSPS.  The NGCC units, which are the

basis of the proposed standard, are projected to meet the proposed standard through their

inherent design.20  As discussed in section 5.5, Nno new conventional coal‐fired boilers, which

would be subject to the proposed NSPS, are projected to be built (excluding new coal built with

CCS).  This implies that the NSPS will require no changes in design or construction of new EGUs

forecasted in the base case.  Thus, , under the baseline projections as well as the sensitivity

analyses presented above, the proposed EGU GHG NSPS will not result in any reduction in

emissions, nor any costs.there would be no expected reduction in emissions and no costs for

the new EGUs whose construction is forecast.

As described above, the base case modeling that EPA performed for this rule (as well as

base case modeling that EPA has performed for other recent air rules) indicates that new fossil

fuel‐fired generating capacity projected to be built through 2020 will be either natural gas‐fired

combined cycle or combustion turbine generation or coal‐fired generation with CCS (the latter

is assumed to be built with support from federal grants).  The EIA’s AEO 2011 modeling makes

similar conclusions.   A number of major utilities have made public announcements consistent

with these modeling results.21

Engineering cost analysis, even outside of a least‐cost system dispatch modeling

environment, reaches similar conclusions.  If one assumes a delivered natural gas price of $5

per million British Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu, which

conservatively reflect forecasted prices from IPM in 2020,22 electricity generated by natural gas

combined cycle units is less expensive on average than coal generation.  A comparison of

levelized wholesale electricity costs for differing generation technologies and natural gas prices

are shown in Figure 5‐4 and Table 5‐43.  It is important to note that both EIA and EPA include a

capital charge rate adder (3 percent) for new conventional coal‐fired generating capacity

                                                      

20 Natural gas combustion turbines are not covered by this proposal. 21 For example: “We have no other coal‐fueled generation planned at this time... When we do need new capacity,

it is highly likely that we will look to natural gas plants instead of coal, especially if natural gas prices remain as

low as projected.” AEP January 1, 2011, Washington Post; “If you actually look at the economics today, you

would be burning gas, not coal,” Jack Fusco, Calpine, 12/1/2010, Marketplace;  “Coal’s most ardent defenders

are in no hurry to build new ones in this environment.” John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas

prices, gas‐fired generation kind of snowplows everything else” Lew Hay, NextEra, 11/1/2010, Dow Jones. 22 EIA projects a U.S. average coal price of $1.65/MMBtu in 2020 ($2009).  Bituminous coals are roughly $2.  EPA

and EIA both project delivered (power sector) natural gas price of roughly $5/mmBtu in 2020.
5‐17

without CCS, which reflects the additional cost of raising capital that is currently reflected in the

marketplace, related at least in part to uncertainty surrounding future greenhouse gas emission

reduction requirements.23  Note that this figure only shows the costs to the generator and does

not reflect the additional social costs that are associated with greenhouse gas emissions or

conventional air pollutants. As the figure shows, with a delivered natural gas price of $5 per

million British Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu, which reflect

forecasted prices from IPM in 2020,24 electricity generated by natural gas combined cycle units

is less expensive on average than coal generation.  

                                                      

23 EIA includes "a 3‐percentage‐point increase is added to the cost of capital for investments in GHG‐intensive

technologies, such as coal‐fired power plants without CCS and CTL plants." Source: EIA AEO 2009, Issues in

Focus. Reflecting Concerns Over Greenhouse Gas Emissions in AEO2009, available at:

http://www.eia.gov/forecasts/archive/aeo09/issues.html

See also http://www.epa.gov/airmarkets/progsregs/epa‐ipm/index.htmlSee

http://www.epa.gov/airmarkets/progsregs/epa‐ipm/index.html and

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm. 24 EIA projects a U.S. average coal price of $1.65/MMBtu in 2020 ($2009).  Bituminous coals are roughly $2.  EPA

and EIA both project delivered (power sector) natural gas price of roughly $5/mmBtu in 2020.
5‐18

($2007)

Figure 5‐4.  Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation

Technologies, EPA25

Notes: Assumptions derived from EPA’s application of IPM.  Technologies include Coal without CCS, Natural Gas Combined

Cycle with natural gas costing $5 per mmBtu, Natural Gas Combined Cycle with $8 per mmBtu costs of natural gas, and

Integrated Gasification Combined Cycle with CCS (with 90 percent capture).  In this graph coal is  a high sulfur bituminous at $2

mmBtu. Conventional Coal is at a heat rate of 8,875 Btu/kWh net, capacity factor of 85 percent assumed across all

technologies.   

It is only when gas prices reach approximately $9.60/mmBtu (in 2007 dollars), that new

coal‐fired generation without CCS becomes competitive, in terms of dollars per megawatt hour

                                                      

25 Although EPA believes that this cost data is broadly representative of the economics between new coal and new

natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new

generating sources that could potentially be built.  To the extent that other types of new units that would be

affected by this rule could be built, they could exhibit different costs than presented here.  For example,

smaller new conventional coal facilities which would be more expensive on a $/kw basis and have a relatively

higher LCOE, and some technologies could potentially have a lower LCOE if fuel could be obtained cheaply and

capital costs remained similar, or lower than, an new base load convention coal plant (petroleum coke or waste

coal).  These differences do not fundamentally change the analysis presented in this chapter.

0

20

40

60

80

100

120

140

Conventional

Coal(no

investor

climate

concern)

Conventional

Coal(w/ CO2

Uncertainty

Adder)

NaturalGas

Combined

Cycle ($5 gas)

NaturalGas

Combined

Cycle ($8 gas)

NaturalGas

Combined

Cycle ($9.60

gas)

Coal + CCS

$/MWh
5‐19

wholesale cost of electricity generation (none of the EPA or EIA sensitivities with alternate

assumptions for natural gas approach this price level).  For context, even EIA’s most pessimistic

gas sensitivity case in the AEO 2011 (“low shale gas recovery per well”) only projects an

electricity sector gas price of $6.79 in 2020 (the “low shale gas recovery per play” scenario

projects a price of $5.93/mmBtu in 2020).

However, iIt is important to note that this analysis is based on assumptions regarding

the average national cost of generation at new facilities.  As reported by the EIA, there is

expected to be significant spatial variation in the costs of new generation due to design

differences, labor wage and productivity differences, location adjustments, among other

potential differences.26  EPA acknowledges that there is some uncertainty around these

estimates, and is unable to provide estimates for all variants.     However, the results are

expected to hold for the majority of situations.  The analysis also does not explicitly consider

new units designed to combust waste coal or petroleum coke (pet coke), which may be affected

by this rule, but also may exhibit different local economics.27  However, the direction of the

relative investment costs and decisions described here results are expected to hold for the vast

majority of situationslocal settings.

Table 5‐43. Estimated Levelized Cost of New Generation Resources from EIA, U.S. Average

(2016)  

Plant Type Capacity

Factor (%)

U.S. Average Levelized Costs (2009 $/ MWh)

for Plants Entering Service in 2016

Levelized

Capital

Cost

Fixed

O&M

Variable

O&M

(Including

fuel)

Transmission

Investment

Total

System

Levelized

Cost

Conventional Coal 85 65.3 3.9 24.5 1.2 94.8

Advanced Coal 85 74.6 7.9 25.7 1.2 109.4

Advanced Coal with CCS 85 92.7 9.2 33.1 1.2 136.5

                                                      

26 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf 27 This analysis also does not explicitly consider new units designed to combust waste coal or petroleum coke (pet

coke), which may be affected by this rule, but can exhibit different economics.  Most other energy models,

including EIA’s application of NEMS, do not consider these technologies for new electricity sources because

they are marginal technologies that are rarely built, and highly dependent upon specific local factors that are

difficult to model and highly speculative (like the ability to obtain a very inexpensive local supply of suitable

fuel).  The models do include these technologies as part of the existing universe of sources, however.  For

context, there are currently 59 units nationwide that are designed to combust either waste coal or petroleum

coke, with a total capacity of roughly 5 GW (or 0.5% of the entire fleet). To the extent that these technologies

would be built absent this rule due to unique local economics and fuel supply, there would be certain costs and

benefits associated with this proposed rule, although they would be expected to be small because these

sources are not often built.  EPA is taking comment and solicits additional information on its consideration of

these technologies in the analysis.
5‐20

Natural Gas‐fired          

    Conventional Combined

Cycle 87 17.5 1.9 45.6 1.2 66.1

    Advanced Combined Cycle 87 17.9 1.9 42.1 1.2 63.1

    Advanced CC with CCS 87 34.6 3.9 49.6 1.2 89.1

    Conventional Comb. Turbine 30 45.8 3.7 71.5 3.5 124.5

    Advanced Combustion

Turbine 30 31.6 5.5 62.9 3.5 103.5

Advanced Nuclear 90 90.1 11.1 11.7 1.0 113.9

Wind 34 83.9 9.6 0 3.5 97.0

Wind ‐ Offshore 34 209.3 28.1 0 5.9 243.2

Solar PV 25 194.6 12.1 0 4.0 210.7

Solar Thermal 18 259.4 46.6 0 5.8 311.8

Geothermal 92 79.3 11.9 9.5 1.0 101.7

Biomass 83 55.3 13.7 42.3 1.3 112.5

Hydro 52 74.5 3.8 6.3 1.9 86.4

Source: EIA, AEO 2011

This rule also proposes an alternative standard that would allow new units to meet the

1,000 lbs CO2/MWh standard using a 30 year averaging period.28  To the extent market

participants have alternative views of both the cost and development of CCS, new conventional

coal‐fired capacity (or IGCC) could be built and operated for some time, with the intention to

apply CCS with high removal efficiency at some later date, in order to achieve the required

average rate over the 30 year period.  Also the above analysis reflects national averages, and in

turn given their specific situation, a market participant could determine that the economics of

building a coal‐powered facility that immediately achieves a CO2 capture and/or removal rate

consistent with the emission standard are favorable.   

Others have done researched to explore the cost and efficiency of varying levels of

capture relative to building alternative other energy technologies.29  This ongoing research

indicates that lower levels of carbon capture at new coal facilities could be cost competitive

with these technologies, and the costs of meeting the proposed emission rate immediately

could be achievable. and economic.  For example, The Clean Air Task Force has compiled data

that indicates the levelized cost of electricity for a new supercritical pulverized coal unit with 50

percent CCS (or 1,080 lb/MWh CO2, which is just above the proposed standard) could be

                                                      

28 IPM does not consider the impact of elevation on performance, and utilizes a uniform elevation performance‐

based assumption. 29 Technical Options for Lowering Carbon Emissions from Power Plants. Clean Air Task Force (June, 2011). Available

at:

http://www.coaltransition.org/filebin/pdf/Technical_Options_for_Lowering_Carbon_Emissions_from_Power.p

df
5‐21

$116/MWh compared to $147/MWh for 90 percent removal.    However, investment decisions

will be made on a case by case basis dependent upon a number of factors, all of which are

difficult to estimate in advance.

5.6.2   Reconstructed Units   

The EPA’s CAA sSection 111 regulations define reconstructed sources as, in general,

existing sources (i) that replace components to such an extent that the capital costs of the new

components exceed 50 percent of the capital costs of an entirely new facility, and (ii) for which

compliance with standards of performance for new sources is technologically and economically

feasible (40 CFR 60.15).  The Agency is aware that, in theory, operators of existing power plants

may choose to reconstruct them, but we are not aware of any announced plans to do so.  This

provision is rarely triggered.  In the proposed NSPS, EPA is taking comment on different

approaches to regulation of reconstructed sources. The options for reconstructed sources, in

general, include (i) establishing the standard of performance at the same level as for new

sources, (ii) establishing the standard performance at 1,800 lb CO2/MWh, or (iii) not

establishing a standard of performance for reconstructed units at this time.   

EPA would not expect either any of these alternatives to change firms’ behavior because

they would be expected to choose technologies that are compliant with the standard even in

the absence of the standard. The costs associated with reconstructing coal‐fired units are likely

to be similar to the cost of building a new natural gas‐fired unit.  Thus, even if this provision is

triggered, EPA believes that the economic analysis outlined above showing that natural‐gas‐

fired generation is significantly more cost effective than building a reconstructed coal plant

results in the choice of natural gas combined cycle or coal with CCS technology (i.e., existing

unit operators are likely to choose technologies for independent market reasons that are

already compliant with the new source NSPS included in this proposal).

5.6.3   Modified and Transitional Units   

Modified and transitional units are described in the preamble and in Chapter 2 of this

RIA. EPA does not anticipate any costs being associated with these units. As explained in the

preamble, The the EPA does not have a sufficient base of information to develop a proposal for

the relatively few affected sources that may take actions that would constitute “modifications,”

as defined under the EPA’s NSPS regulations, and therefore be subject to requirements for new

sources. A modification is any physical change in, or change in the method of operation of, a

source that increases the amount of any air pollutant emitted by the source or results in the

emission of any air pollutant not previously emitted.  The EPA is soliciting comment on this
5‐22

issue, but in the meantime, the EPA is not proposing standards for modifications.  The Agency

believes that it does not, at present, have adequate information as to the type of action, its

costs, or the amount of its effect on CO2 emissions, on which to base a proposed standard of

performance for modified sources.  Therefore, sources that undertake physical or operational

changes that increase their maximum achievable hourly CO2 emission rate will be treated as

existing sources, and thus they  not be subject to the proposed EGU GHG NSPS requirements

for new sources.

5.6.4 Transitional Units

In the proposal, EPA identifies transitional sources as those sources that have received

final PSD permits, but have not actually commenced construction. EPA is proposing that as long

as units commence construction within a set amount of time, construction can proceed without

being affected by this rule.  While this proposed rule sets no standard for the transitional

source subcategory of new sources, these sources may become subject to an existing source

standard in a subsequent rulemaking.  

EPA believes that there are approximately 15 such units discussed previously in Chapter

2. Historically, obtaining a permit does not guarantee that a unit will end up being constructed.  

In the last 10 years, 88 coal plants have been permitted.  Of those, 40 (or fewer than half) have

actually commenced construction.  Thirty projects have been cancelled and approximately 15

sources (the transitional sources) have active permits.  Based on this history and current

economic conditions, EPA believes that at least some number of these units would not likely

proceed to construction, regardless of the requirements of this rule. For these units, this rule

adds no costs.  Once a unit has received a final PSD permit, it must commence construction

within 18 months. The units EPA has potentially identified as “transitional” were permitted

prior to this rule being proposed. EPA is proposing that as long as units commence construction

within 12 months, construction can proceed without being affected by this rule.  For these

units, this rule adds no additional costs and will not result in any monetized benefits.

In the absence of this rule, EPA believes the coal units within this transitional category

that are most likely to commence construction are those that have received public incentives to

install CCS. Under the proposed rule, these units could commence construction within the

proposed time‐frame without incurring any requirement to reduce CO2 emissions.  EPA believes

that the economics demonstrated above also apply to the other transitional units; such that

building natural gas‐fired combined cycle generation is likely to be a less expensive option than

traditional coal‐fired generation, even in the absence of this rule.  The developers of the
5‐23

projects already permitted are likely considering these economic factors and may ultimately

choose not to commit to actual construction of these previously proposed coal and petroleum

coke plants.

5.7   Summary of Costs, Economic, and Energy Impacts of the Proposed Rule for New,

Reconstructed, Modified, and Transitional Electric Generating Units

Under a wide range of electricity market conditions – including EPA’s baseline scenario

as well as multiple sensitivity analyses – EPA projects that the industry will choose to construct

new units that already meet these standards, regardless of this proposal.  As a result, EPA does

not anticipate that the proposed EGU GHG NSPS will result in notable CO2 emission changes,

energy impacts, or costs for new units constructed by 2020.  Likewise, the Agency does not

anticipate any notable impacts on the price of electricity or energy supplies. EPA does not

anticipate that the proposed EGU GHG NSPS will result in notable CO2 emission changes, energy

impacts, or costs for new units constructed by 2020.  EPA believes that the industry will choose

to construct new units that already meet these standards due to current and expected

economic conditions, regardless of this proposal.  Likewise, the Agency believes this rule will

not have notable impacts on the price of electricity or energy supplies in this country.

Additionally, for the reasons described above, the proposed rule is not expected to raise any

reliability concerns, since reserve margins will not be impacted and the rule does not impose

any requirements on existing facilities.

This finding is supported by EPA modeling of the base case, which does not project the

future construction of new coal‐fired capacity beyond 2 GW of coal with CCS, which is built in

response to the financial incentives for CCS included in the Emergency Economic Stabilization

Act of 2008 and American Recovery and Reinvestment Act of 2009, which authorized and/or

appropriated funding to DOE for CCS deployment.  In the short‐term, most new capacity is

projected as a mix of wind and natural gas in response to the competitive marketplace for fuels

and other energy policies (such as tax credits and state renewable portfolio standards).  

In addition, future electricity demand expectations have trended downwards in recent

forecasts, reducing the need for new capacity by 2020 (see Chapter 4 for more discussion on

future electricity demand).  Electricity demand is anticipated to grow by roughly 1 percent per

year, and total electricity demand is projected to be 4,104 billion kWh by 2015.  Table 5‐2

shows current electricity generation alongside EPA’s projection for 2020 using IPM.  EPA’s IPM

modeling for this rule relies on EIA’s Annual Energy Outlook for 2010’s electric demand forecast

for the US and employs a set of EPA assumptions regarding fuel supplies, the performance and

cost of electric generation technologies, pollution controls, and numerous other parameters.  
5‐24

5.8 Limitations

Although there is a significant amount of information that points to a future where

conventional coal (without CCS) is likely to be more costly to build relative to other, lower

emitting sources of electricity (regardless of whether the power sector is regulated for

greenhouse gases or not), the Agency acknowledges the possibility that in unusual situations, a

company could find it advantageous to build a conventional coal facility (or other potentially

affected facility) if there were no greenhouse gas requirements (i.e., if the social and

environmental damages of carbon emissions remain as unpriced externalities not reflected in

project economics).  While it is difficult to identify and evaluate hypothetical scenarios where

this could come to fruition inthe very limited and localized circumstances where this may occur,

we note that today’s action for new sources would likely prevent these occurrences, since new

sources would be required to meet the proposed NSPS standards.  However, in such a case the

rule would also produce benefits from any reduced emissions of greenhouse gases and other

air pollution.

5.9 Benefits of Reduced Regulatory Uncertainty

Most major actors in the power sector anticipate eventual CO2 emissions policy for

power plants, a performance standard for new sources can reduce uncertainty by setting clear

parameters for the planning of new generation. The presence of sustained regulatory

uncertainty may affect the decisions of firms, leading them to potentially forgo more profitable

investment strategies that would occur in the presence of increased regulatory certainty

(Teisberg 1993, Hoffmann et al., 2009).  In particular, uncertainty regarding future greenhouse

gas policy may affect firms’ decisions with regards to the timing and types of investments made

in new electricity generating capital (Blyth et al., 2007).  A significant reduction in regulatory

uncertainty may then increase the expected profits for firms within the electricity generating

sector by allowing them to optimize investment decisions with a greater understanding as to

the future operating environment (e.g., Reinelt and Keith, 2007; Patiño‐Echeverri et al., 2009).  

EPA is not able to directly quantify or monetize this benefit at this time.

5.810 Comparison of Emissions Differences offrom Generation Technologies

As discussed earlier in this chapter, natural gas combined cycle units are on average

expected to be more economical to build and operate than new coal units.  These natural gas

units also have lower emission profiles for CO2 and criteria air pollutants than new coal units.

While the baseline forecast suggests that the proposed EGU GHG NSPS is anticipated towill

have no monetized negligible costs or quantified benefits under a range of likely market

conditions, it is instructive to consider the differences in emissions of CO2 and conventional air
5‐25

pollutants between the two types of units.  EPA does not anticipate any incremental changes to

coal or natural gas capacity as a result of this rule as proposed, and as such, these comparisons

are purely for illustrative purposes.   

As Table 5‐54 below shows, emissions from a typical new natural gas combined cycle

facility are significantly lower than those from a traditional coal unit.30  For example, a typical

new supercritical pulverized coal facility that burns bituminous coal in compliance with new

utility regulations (e.g., CSAPR and MATS) would have considerably greater CO2, sulfur dioxide

(SO2), NOx, toxic metals, acid gases, and particulate emissions than a comparable natural gas

combined cycle facility.  A typical natural gas combined cycle unit is expected to emits two

million metric tons less CO2 per year than a typical new conventional coal unit, as well as,

9302,000 fewer short tons SO2 and 1,200 fewer short tons of NOx each year.  Importantly, these

differences in emissions assume a new coal unit that complies with all applicable regulations,

including MATS. Reductions in SO2 emissions are a particularly significant driver for monetized

health benefits, as SO2 is a precursor to the formation of particulates in the atmosphere, and

particulates are associated with premature death and other serious health effects.   Further

information on these pollutants’ health effects is included in the next subsection.

                                                      

30 Estimated emissions of CO2, SO2, and NOX for the illustrative new coal and natural gas combined cycle units

could vary depending on a variety of assumptions including heat rate, fuel type, and emission controls, to name

a few.
5‐26

Table 5‐54.  Illustrative Emissions Profiles, New Coal and Natural Gas‐Fired Generating Units31

Conventional Coal Natural Gas CC Coal with CCS

SO2  tons/year 2,000 ‐‐‐ Negligible

NOx  tons/year 1,400 200 1,100

CO2  tons/year 3.6 million 1.6 million 0.45 million

Conventional Coal Natural Gas CC Coal with CCS

Emissions

(tons/year)

Emission Rate

(lbs/MWh

net)

Emissions

(tons/year)

Emission Rate

(lbs/MWh

net)

Emissions

(tons/year)

Emission Rate

(lbs/MWh

net)

SO2 940 0.42 10 0.0041 50 0.022

NOx 1,400 0.62 200 0.09 1,100 0.47

CO2 3.6 million 1,800 1.7 million 820 0.4 million 200

Notes: SO2 and NOx in short tons, CO2 in metric tons. As discussed in Section 5.4, the illustrative units represent relative

emissions for new well controlled 600 MW (net) baseload units running at 85 percent capacity factor (85% capacity factor

reflects operation of new baseload units and does not necessarily reflect the historic capacity factors of existing units with

specifications similar to these illustrative units). Assumed coal is high sulfur bituminous with scrubber and SCR, data are based

on EPA assumptions used in IPM.

Notes: SO2 and NOx in short tons, CO2 in metric tons. See Figure 5‐4 for a description of the technologies, including the modeled

fuel and pollution control configuration, and their associated levelized cost that correspond to these emission estimates.

Relative emissions for new well controlled 600 MW (net) units running at 85 percent capacity factor. Assumed coal is high sulfur

bituminous with scrubber and SCR, data is based on EPA assumptions used in IPM.

5.911. Benefits of Reducing GHGs and Conventional Pollutants

Because emissions of CO2 and criteria air pollutants adversely affect human health and

welfare, the differences in emissions presented above translate into differences in the external

social costs associated with different generation technologies. Here we provide a general

discussion about the differences in emissions of CO2 and criteria air pollutants in the previous

illustrative example.

As shown in this illustrative example, natural gas combined cycle units are expected to

be more economical to build and operate on average than new coal units and have lower

emissions of CO2 and conventional pollutants. While baseline forecasts suggest that the

proposed NSPS will have no notable costs or monetized quantifi benefits, it is instructive to

                                                      

31 The emissions presented here are estimated on an output basis to enable easier comparisons and to illustrate

the potential impacts of moving from new coal to new natural gas.  This analysis assumes representative new

units and does not reflect the full array of new generating sources that could potentially be built (e.g., a small

new conventional coal plant or a waste coal or petroleum coke facility).  However, the emissions associated

with other facilities that could be built, and which would be subject to this proposal, would not change

noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and would

emit similar levels of SO2, NOX, and CO2, on an output basis).
5‐27

consider the benefits associated with the differences in emissions of CO2 and criteria air

pollutants in the previous illustrative example.  EPA does not anticipate any incremental

changes to new coal or natural gas capacity as a result of this rule, and as such, these

comparisons are purely for illustrative purposes.  

5.9.1 Social Cost of Carbon

The social cost of carbon (SCC) is a metric to estimate the monetary value of benefits

associated with marginal changes in CO2 emissions, and may therefore be utilized to

understand the value of the difference in CO2 emissions between the two hypothetical

representative units discussed in Ssection 5.8104.  The SCC is an estimate of the monetized

damages associated with an incremental increase in carbon emissions in a given year.  It is

intended to include (but is not limited to) changes in net agricultural productivity, human

health, property damages from increased flood risk, and the value of ecosystem services due to

climate change.  Federal agencies typically use SCC estimates to assess the benefits of

rulemakings that achieve marginal reductions in CO2 emissions.  These estimates were

developed through an interagency process that included EPA and other executive branch

entities, and concluded in February 2010.  The SCC Technical Support Document (SCC TSD)

provides a complete discussion of the methods used to develop these SCC estimates.32    

The interagency group selected four SCC values for use in regulatory analyses: $7, $26,

$42, and $81 per metric ton of CO2 emissions in 2020, in 2007 dollars.33,34 The first three values

are based on the average SCC from three integrated assessment models, at discount rates of 5,

3, and 2.5 percent, respectively.  SCCs at several discount rates are included because the

literature shows that the SCC is quite sensitive to assumptions about the discount rate, and

because no consensus exists on the appropriate rate to use in an intergenerational context. The

fourth value is the 95th percentile of the SCC from all three models at a 3 percent discount rate.  

                                                      

32 Docket ID EPA‐HQ‐OAR‐2009‐0472‐114577, Technical Support Document: Social Cost of Carbon for Regulatory

Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with

participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture,

Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection

Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget,

Office of Science and Technology Policy, and Department of Treasury (February 2010).  Also available at

http://epa.gov/otaq/climate/regulations.htm   33 Note that upstream emissions changes were not considered for this rule.  There may be changes in greenhouse

gas emissions (in particular, methane) due to changes in fossil fuel extraction and transport in response to this

proposal, but those were not quantified. 34 The interagency group concluded that a global measure of the benefits from reducing U.S. GHG emissions should

be the standard practice when conducting regulatory impact analysis in support of federal rule makings.  See

Interagency Working Group on Social Cost of Carbon.  2010.  Technical Support Document: Social Cost of

Carbon for Regulatory Impact Analysis Under Executive Order 12866.
5‐28

It is included to represent higher‐than‐expected impacts from temperature change further out

in the tails of the SCC distribution.  

The SCC increases over time because future emissions are expected to produce larger

incremental damages as physical and economic systems become more stressed in response to

greater climatic change.  Note that the interagency group estimated the growth rate of the SCC

directly using the three integrated assessment models rather than assuming a constant annual

growth rate. This helps to ensure that the estimates are internally consistent with other

modeling assumptions.  Table 54‐651 presents the SCC estimates for the years 2015 to 2050.   

In order to calculate the dollar value for emission reductions, the SCC estimate for each

emissions year would be applied to changes in CO2 emissions for that year, and then discounted

back to the analysis year using the same discount rate used to estimate the SCC.

When attempting to assess the incremental economic impacts of carbon dioxide

emissions, the analyst faces a number of serious challenges.  A recent report from the National

Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty,

speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the

effects of past and future emissions on the climate system, (3) the impact of changes in climate

on the physical and biological environment, and (4) the translation of these environmental

impacts into economic damages.35  As a result, any effort to quantify and monetize the harms

associated with climate change will raise serious questions of science, economics, and ethics

and should be viewed as provisional.   

The interagency group noted a number of limitations to the SCC analysis, including the

incomplete way in which the integrated assessment models capture catastrophic and non‐

catastrophic impacts, their incomplete treatment of adaptation and technological change,

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding

risk aversion.  Current integrated assessment models do not assign value to all of the important

physical, ecological, and economic impacts of climate change recognized in the climate change

literature because of lack of precise information on the nature of damages and because the

science incorporated into these models understandably lags behind the most recent research.  

The limited amount of research linking climate impacts to economic damages makes the

interagency modeling exercise even more difficult.  The interagency group hopes that over time

researchers and modelers will work to fill these gaps and that the SCC estimates used for

                                                      

35 National Research Council (2009). Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use.

National Academies Press.  See docket ID EPA‐HQ‐OAR‐2009‐0472‐11486.
5‐29

regulatory analysis by the Federal government will continue to evolve with improvements in

modeling. It is important to emphasize that the interagency process is committed to updating

these estimates as the science and economic understanding of climate change and its impacts

on society improves over time.  Specifically, they have set a preliminary goal of revisiting the

SCC values within two years, or at such time as substantially updated models become available,

and to continue to support research in this area.  Additional details on these limitations are

discussed in the SCC TSD.

Table 5‐65. Social Cost of CO2, 2015‐2050a (in 2007 dollars)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th percentile

2015 $6 $24 $38 $73

2020 $7 $26 $42 $81

2025 $8 $30 $46 $90

2030 $10 $33 $50 $100

2035 $11 $36 $54 $110

2040 $13 $39 $58 $119

2045 $14 $42 $62 $128

2050 $16 $45 $65 $136

a The SCC values vary depending on the year of CO2 emissions and are defined in real terms.are dollar‐year and

emissions‐year specific.

5.9.2 Health Impacts of SO2 and NOx  

As shown in the Table 5‐4, a natural gas unit emits approximately 2,000 tons less SO2

and 1,200 tons less NOx annually when compared to a conventional coal unit.  SO2 is a

precursor for fine particulate matter (PM2.5) formation.  NOX is a precursor for PM2.5 and ozone

formation.  As such, reductions of SO2 and NOX would in turn lower overall ambient

concentrations of these pollutants as well as PM2.5 and ozone.  Reducing exposure to PM2.5 and

ozone is associated with significant human health benefits, including avoiding mortality and

morbidity.  Researchers have associated PM2.5 and ozone exposure with adverse health effects

in numerous toxicological, clinical, and epidemiological studies (U.S. EPA, 2009; U.S. EPA, 2006).

Health effects associated with exposure to PM2.5 include premature mortality for adults and

infants, cardiovascular morbidity such as heart attacks and hospital admissions, and respiratory

morbidity such as asthma attacks, bronchitis, hospital and emergency room visits, work loss

days, restricted activity days, and respiratory symptoms.  Health effects associated with
5‐30

exposure to ozone include premature mortality and respiratory morbidity such as asthma

attacks, hospital and emergency room visits, and school loss days. For a full discussion of the

human health benefits of reducing SO2 and NOX emissions from power sector sources, including

reducing methyl mercury, SO2, and NO2 exposure, please refer to the RIA for CSAPR (U.S. EPA,

2011).

In addition to human health benefits, reducing SO2 and NOX emissions would also result

in human welfare improvements by improving ecosystem services—the benefits that the public

obtains from ecosystems that directly or indirectly contribute to social welfare.  SO2 and NOX

emissions can adversely impact vegetation, certain manmade materials, acidic deposition,

nutrient enrichment, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008).  Reducing these

harmful emissions improves human welfare.  For more information about the welfare benefits

of SO2 and NOX emission reductions from power sector sources, please refer to the Regulatory

Impact Analysis for the CSAPR (U.S. EPA, 2011).

EPA is unable to quantify any portion of the potential Because the health or and welfare

benefits of SO2 and NOx emissions in terms of incidences of health effects avoided or monetized

value of health or welfare improvements depend on due to uncertainty lack of specificity in

power plant location, the potential benefits cannot be quantified precisely for the purposes of

and years of operation for this illustrative example.  However, reducing one thousand tons of

annual SO2 from U.S. EGUs in 2020 has been estimated36 to yield between 3 and 9 incidences of

                                                      

36 The SO2 and NOX benefit per‐ton (BPT) values presented here consist of only PM2.5‐related health benefits from

reductions in SO2 and NOX (precursors to PM2.5 formation).  EPA relied on air quality modeling used to develop

a previous rulemaking affecting power sector emissions of SO2 and NOX to develop these BPT values (Air Quality

Modeling Technical Support Document for the final Transport Rule;

http://epa.gov/airtransport/pdfs/AQModeling.pdf). EPA utilized Transport Rule (Cross‐State Air Pollution Rule)

modeling rather than air quality modeling of EPA’s Mercury and Air Toxics Standards (MATS) because EPA did

not estimate NOX BPT values for MATS and because the utilized Transport Rule modeling reduced emissions of

SO2 and NOX independently, allowing for better estimation of PM2.5‐related SO2 and NOX BPT values.  The air

quality modeling utilized reflects emission reductions in the eastern U.S. In order to better understand the

relative difference between BPT values for emission reductions in the east and west, see Table 5C‐3 of the

MATS Regulatory Impact Analysis (RIA) <www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf>. Using this

existing air quality modeling, EPA used BenMAP (www.epa.gov/air/benmap) to estimate the benefits of air

quality improvements using projected 2020 population, baseline incidence rates, and economic factors.  These

BPT values are methodologically consistent with those reported in Fann et al. (2009).  As EPA models avoided

premature deaths among populations exposed to levels of PM2.5, we have lower confidence in levels below

the lowest measured level (LML) for each study.  However, studies using data from more recent years, during

which time PM2.5 concentrations have fallen, continue to report strong associations with mortality.  For more

information refer to the MATS RIA.  The average BPT values reflect a specific geographic distribution of SO2 and

NOX reductions resulting in a specific reduction in PM2.5 exposure and may not fully reflect local or regional

variability in population density, meteorology, exposure, baseline health incidence rates, or other factors that

might lead to an over‐estimate or under‐estimate of the actual benefits associated with PM2.5 precursors.  
5‐31

premature mortality avoided annually and annual monetized PM2.5‐related health benefits

(including these incidences of premature mortality avoided) of between $30 million and $75

million (2007$) using a 3% discount rate or between $28 million and $67 million (2007$) using a

7% discount rate. (where the range is due to EPA’s use of two alternative primary estimates of

PM2.5 mortality impacts, a lower primary estimate based on Pope et al. (2002) and a higher

primary estimate based on Laden et al. (2006)). Additionally, reducing one thousand tons of

annual NOX from U.S. EGUs in 2020 has been estimated37 to yield up to 1 incidence of

premature mortality avoided annually and annual monetized PM2.5‐related health benefits

(including these incidences of premature mortality avoided) of between $2.5 million and $6.2

million (2007$) using a 3% discount rate or between $2.3 million and $5.6 million (2007$) using

a 7% discount rate.38

5.102   SensitivityIllustrative Analysis of the Social Costs of New Generating Sources

As the analysis in sections 5.5 and 5.6 demonstrated, under a wide range of likely

electricity market conditions – including EPA’s baseline scenario as well as multiple sensitivity

analyses – EPA projects that the industry will choose to construct new units that already meet

these standards, regardless of this proposal.  

In this section, we consider the unlikely scenario where future market conditions

support the construction of new conventional (advanced, but without CCS) coal capacity during

                                                                                                                                                                              

These BPT values are purely illustrative as EPA does not assert a specific location for the illustrative coal and

natural gas combined cycle units and is therefore unable to specifically determine the population that would be

affected by their emissions.  Therefore, the benefits for any specific unit can be very different than the

estimates shown here.  EPA notes that the BPT estimates do not reflect emission reductions after

implementation of EPA’s Mercury and Air Toxics Standards.   37 Ibid. 38 The SO2 and NOX benefit per‐ton values presented here used to estimate these ranges consist of only PM2.5‐

related health benefits from reductions in SO2 and NOX (precursors to PM2.5 formation).  EPA relied on air

quality modeling (Air Quality Modeling Technical Support Document for the final CSAPRTransport Rule;

http://epa.gov/airtransport/pdfs/AQModeling.pdf) used to develop a previous rulemaking affecting power

sector emissions of SO2 and NOX to develop these benefit per‐ton values, which are methodologically

consistent with those reported in Fann et al. (2009).  As such, the national average benefit per‐ton values

reflect a specific geographic distribution of SO2 and NOX reductions resulting in a specific reduction in PM2.5

exposure and may not fully reflect local or regional variability in population density, meteorology, exposure,

baseline health incidence rates, or other factors that might lead to an over‐estimate or under‐estimate of the

actual benefits associated with PM2.5 precursors.  These benefit per‐ton values are purely illustrative as EPA

does not assert a specific location for the illustrative coal and natural gas combined cycle units and is therefore

unable to specifically determine the population that would be affected by their emissions.  Therefore, the

benefits for any specific unit can be very different than the estimates shown here.  EPA notes that the benefit

per‐ton estimates do not reflect emission reductions after implementation of EPA’s Mercury and Air Toxics

Standards.  EPA provides two estimates of PM2.5 mortality impacts, a low estimate based on Pope et al. (2002)

and a high estimate based on Laden et al. (2006).
5‐32

the analysis period in the absence of the rule.  The analysis in this section indicates that in this

scenario, the proposed EGU GHG NSPS is highly likely to provide net benefits to society as a

whole.

The starting point for this analysis is EPA believes that, given expected energy demand

along with fuel and capital prices, new conventional coal capacity is unlikely to be constructed

over the time horizon of interest in this analysis. As part of this explanation we provide an the

illustrative, but representative, comparison (presented in Figure 5‐4 above) of the relative

private costs of constructing and operating a representative new conventional coal EGU and a

representative NGCC unitnatural gas combined cycle systems to provide the same generation

services (see Figure 5‐4).

39  This comparison shows that, at forecast relative fuel prices, there is

a significant difference in the levelized cost of these two generating technologies. However, in

the context of a social welfare analysis, the appropriate comparison between multiple options

is on the basis of benefits and costs to society as a whole, and not solely the private cost to an

investor.  

From the perspective of society, the appropriate cost comparison for new generation

capacity should account for the pollution damages associated with the competing generation

technologies in addition to private generating costs.   This section further explores how the

potential social benefits and costs of this NSPS standard may change across a wide range of

natural gas prices, a key factor in the potential cost of the policy.  It begins by estimating

illustrative environmental damages per MWh for coal relative to gas generation and then uses

those these estimates to conduct an illustrative breakeven sensitivity analysis for the potential

social costs of the policy in this illustrative example.

40

It should be emphasized that the analysis presented here is illustrative, although EPA

believes that it leads to a robust conclusion.  From an analytical perspective, the challenge is to

estimate expected benefits and costs given uncertainty about future market conditions.  An

ideal benefit‐cost analysis would first model projected generation capacity and capacity

                                                      

39 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in

the form of electricity generating services. We assume in the discussion that the benefits of electricity

production to consumers outweighs the private and social investment cost. However, at particularly high fuel

prices this might not be the case. For a discussion of the usefulness ofwhen comparing a the levelized costs

analysis of different generating technologies, and when it provides informative results and when it does not,

see, for example, Joskow 2010 and 2011.   40 From an economic perspective, the analysis in sections 5.5 and 5.6 considered the net benefits of the rule under

expected market conditions, and found those to be zero (because the rule would not affect what new capacity

is built under those market conditions).  The analysis in this section, while still purely illustrative, is an initial

step toward estimating the expected net benefits of the rule as a function of market conditions.
5‐33

additions for every plausible set of market conditions (e.g., different combinations of natural

gas and coal supplies and electricity demand).  The effects of the proposed EGU GHG NSPS

could then be estimated in each of those scenarios including the resulting estimated benefits

and costs (which would depend on the amount of new generation capacity built, the

technologies used, the location of new generating plants, and so on). The analysis would then

estimate the conditional probability distribution of those outcomes (for example, the

probability distribution of future natural gas prices or future electricity demand conditional on

the current information on supply).  Finally, the analysis would integrate the estimated benefits

and costs over the conditional probability distribution of outcomes, to arrive at the expected

net benefits of the rule.

The analysis just described is beyond the scope of the current RIA, and EPA believes that

the sensitivity cases presented in section 5.6.1, combined with the illustrative analysis here,

provide a robust picture of the likely costs and benefits of the standard.  Nonetheless, EPA is

inviting comment on whether a more detailed analysis would be practical, feasible, and an

effective use of limited analytical resources, and if so, how it might be carried out and what

information it would be expected to provide.  If commenters believe that such an analysis

would be practical and appropriate, EPA invites comment on what variables should be treated

as uncertain (e.g., natural gas and coal prices, electricity demand) and on the specific

conditional and potentially joint probability distributions that should be used for the future

state of those variables.

In the spirit of the “ideal” analysis just described, in the remainder of this section EPA

provides an illustrative analysis focusing on uncertainty in the price of natural gas, which is a

key determinant of the economics of electricity generation and therefore the potential impacts

of this proposed rule.

5.102.1   Illustrative Environmental Damages per MWh  

As previously discussed in this chapter, the damages associated with emissions from

new sources of electricity generation are greater for coal‐fired units than for natural gas

combined cycle units (even when accounting for compliance with EPA’s recent Mercury and Air

Toxics Standard).  To gauge the general effect of accounting for both the private and external

costs of electricity generation for new generation options we continue with the illustrative
5‐34

example from Section 5.10.  The external costs are defined as the damages associated with

pollution that are not accounted for in the private investor's decision making.41  

To illustrate the external costs associated with new generation options we combine the

illustrative emission profiles for the new units, as provided in Table 5‐54, and the illustrative

emissions and damage estimates discussed in the previous two sections.

42  Specifically, for each

generating technology we multiply the CO2 emissions by the estimates of the SCC and add that

to the SO2 emissions43 multiplied by the PM2.5‐related SO2 benefit per‐ton estimates,44

subsequently dividing by MWh45 to estimate the external costs per unit of generation.

Table 5‐7 reports the additional pollution damages from the illustrative new coal plant

relative to the illustrative new natural gas plant given different mortality risk studies and

assumptions about the discount rate.   These pollution damages should be relatively invariant

across natural gas prices and other economic factors.  Using this approach the damages

associated with generation from the illustrative new coal unit are, dDepending on the discount

rate and epidemiology mortality risk study used, damages associated with generation from a

representative new coal unit are $118 to $8199 per MWh, while damages associated with the

illustrative new natural gas combined cycle unit are $3 to $3129 per MWh (2007$).46   

It is important to note that although the ranges appear to overlap, for any set of

assumptions (i.e.,For any specific epidemiology mortality risk study and choice of SCC value)

estimate the pollution damages associated with new coal generation in this illustrative, but

representative, example are significantly higher than those associated with new natural gas

combined cycle generation in this illustrative, but representative example.  For example,

considering the SO2 per ton damages based on Pope et al. 2002 using a 7% discount rate and

the SCC estimate based on the 3% discount rate, new generation based on conventional coal in

                                                      

41 See Baumol and Oates, 1988.   42 Only the direct emissions of twothree pollutants (CO2 and, SO2, and Nox) are considered in this illustrative

exercise.  Other pollutants and lifecycle emissions are not considered. 43 See footnote 17 in section 5.10. 44 See footnote 213 in section 5.121 for a description of the benefit‐per‐ton values. In this exercise they are

interpreted as damage‐ per‐ton values. 45 See footnote 179 in section 5.10. 46 Different discount rates are applied to SCC than to the other damage estimates because CO2 emissions are long‐

lived and subsequent damages occur over many years.  Moreover, several rates are applied to SCC because the

literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the

appropriate rate to use in an intergenerational context.  The SCC interagency group centered its attention on

the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the “SCC

TSD,” Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social

Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA‐HQ‐OAR‐2009‐

0472‐114577. http://www.epa.gov/otaq/climate/regulations/scc‐tsd.pdf for details.
5‐35

this example would result in an additional $1724 per MWh in pollution damages compared to a

new NGCC plant. Alternately, damages that reflect the SO2 per ton damage estimate based on

Laden et al. 2006 using a 3% discount rate and the SCC estimate based on a 2.5% discount rate

suggest an additional $3352 of pollution damages per MWh from a new conventional coal unit

compared to a new NGCC plant. Table 5‐6 reports the additional pollution damages from the

illustrative new coal plant relative to the illustrative new natural gas plant given different

mortality risk studies and assumptions about the discount rate.   These pollution damages

should be relatively invariant across natural gas prices and other economic factors.
5‐36

Table 5‐76. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New

Natural Gas Combined Cycle Unit47

SCC Discount Rate Damages from CO2

5% $3

3% $11

2.5% $18

3% (95th percentile) $34

Damages from SO2 Only

Discount Rate Applied to Health Co‐Benefits

Mortality‐Risk

Study 3% Discount Rate 7% Discount Rate

Pope (2002) $6 $6

Laden (2006) $16 $15

Combined Damages from CO2 and SO2

Discount Rate Applied to Health Co‐Benefits

SCC Discount Rate 3% Discount Rate 7% Discount Rate

5% $917 ‐ $1937 $916 ‐ $1733

3% $1725 ‐ $2745 $1724 ‐ $2542

2.5% $2432 ‐ $3352 $2431 ‐ $3249

3% (95th percentile) $4150 ‐ $5070 $4049 ‐ $4866

Notes: Values in first two tables may not sum due to rounding.

The range of costs within each SCC value and discount rate for conventional SO2 pollution damages pairing reflects the use of two core

estimates  of PM2.5‐related estimates of premature mortality, Pope et al. (2002) representing the lower of our core estimates and Laden et al.

(2006) represent the higher of our core estimates.  Assumed coal is high sulfur bituminous with scrubber and SCR.  The combinations of health

studies and discount rates represent lower and higher valuations of impacts of NOx and SO2 emissions in the Eastern U.S. EPA has evaluated the

range of potential impacts per MWh by combining all SCC values with health damages values at the 3 percent and 7 percent discount rates. To

be consistent with concepts of intergenerational discounting, values for health damages, which occur within a generation, would only be

combined with SCC values using a lower discount rate, e.g. the 7 percent health damages estimates would be combined with 5 percent or lower

SCC values, but the 3 percent health damages would not be combined with the 5 percent SCC value.  While the 5 percent SCC and 3 percent

health damages estimate falls within the range of values we analyze, this individual estimate should not be used independently in an analysis,

as it is represents a combination of discount rates that is unlikely to occur. Combining the 3 percent SCC values with the 3 percent health

damage values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts.

As with the relative investment costs of a new coal unit and a new natural gas combined

cycle system, a comparison of the actual environmental damages associated with these two

                                                      

47 The damages presented here are estimated on an output basis to enable easier comparisons and to illustrate the

potential impacts of moving from new coal to new natural gas.  This analysis assumes representative new units

and does not reflect the full array of new generating sources that could potentially be built (e.g., a comparison

of a small new conventional coal plant with a small natural gas plant, or a comparison of a waste coal or

petroleum coke facility to a natural gas plant of a comparable size and capacity factor).  However, the damages

associated with other facilities that could be built, and which would be subject to this proposal, would not

change noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and

would emit similar levels of SO2 and CO2, on an output basis) except for differences in local conditions, as

discussed below.
5‐37

technologies depends on the location under consideration and the specific fuels that would be

used.  An ideal benefit‐cost analysis n ideal social cost comparison of these technologies would

account for these local circumstances (and consider alternative sources of generation).48  

HoweverThat said, these factors will not change the qualitative conclusion. tThe damages

associated with CO2 emissions, which is the focus of this rule, do not depend on the location of

generation. Furthermore, the damages associated with sulfur dioxide emissions from a new

very well‐controlled coal‐fired unit firing low‐sulfur coal would still be greater than the damages

from a new natural gas combined cycle unit independent of the location.

The conclusion from this analysis is that there are significant environmental damages

associated with electricity generation from a representative new conventional coal unit relative

to a representative new natural gas combined cycle unit.49 Other studies of the social costs of

coal and natural gas fired generation provide similar findings (Muller et. al, 2011; NRC, 2009).50

An important implication is that if market conditions changed sufficiently so that new coal units

became   

Overall, these environmental damages suggest that, even if it were the case that the

private cost of natural gas generation began to rise relative to the private cost of coal

generation, there would still remain a substantial difference in the overall cost to society

between these two technologies.  In other words, the damages from air pollution suggest that,

even in cases where new coal may be marginally more economic profitable to operate, these

                                                      

48 EPA does not assert a specific location for the illustrative coal and natural gas combined cycle units and is

therefore unable to specifically determine the population that would be affected by their SO2 and NOX

emissions.  Therefore, the benefits for any specific unit can be very different than the estimates shown here.    49 As previously noted in this section and the previous sections on the costs and damages associated with these

technologies, EPA does not assert a specific location for the illustrative coal and natural gas combined cycle

units and is therefore unable to specifically determine the population that would be affected by their SO2 and

NOX emissions.  Therefore, the benefits for any specific unit can be very different than the estimates shown

here, though the proportion associated with CO2, which is a well dispersed global pollutant, will not be affected

by location.   50 Muller et al. 2011 conclude that, “coal‐fired power plants have air pollution damages larger than their value

added”, while the same is not true for natural gas plants (see Table 5). However, these comparisons are based

on typical existing coal and natural gas units, including natural gas boilers, and are not sensitive to location. The

NRC 2009 study shows that only the most polluting natural gas units may cause greater damages than even the

least polluting existing coal plants (compare Tables 2‐9 and 2‐15). However, the NAS comparison does not

compare new units located in the same place, and so some of the natural gas units with the greatest damages

may be attributable to their location, and includes natural gas steam boilers, which have a higher emission

rates per unit of generation than natural gas combined cycle units.   
5‐38

new units are still likely to impose a net cost to society relative to a new natural gas plant.  This

idea is discussed in more detail in the next section.51    

5.102.2 Social Benefits and Costs across a Range of Gas Prices ‐ Breakpoint Sensitivity

Analysis

We now discuss how a consideration of the environmental damages associated with

new coal and natural gas EGUs informs the comparison of the two technologies from the

standpoint of net benefits – building on the illustrative comparison of a representative new coal

unit and a representative natural gas unit developed in Sections 5.10 and 5.11

Section 5.11 details illustrative environmental damages associated with a typical new

coal plant compared to a new natural gas plant.  The social cost of a policy should account for

not only the difference in private cost between the two technologies, but also the difference in

the external costs (environmental damages) associated with the two technologies.

At today’s current natural gas prices relative to other fuels, the difference in the

estimatedprivate levelized cost of electricity for these illustrative facilitiesa representative

NGCC unit is roughly $27 per MWh less than for a representative new conventional coal unitin

favor of natural gas combined cycle at today’s gas prices (see Figure 5‐4).   This is consistent

with EPA’s projection, discussed at length above, that Because the underlying economics at

current gas prices favor the construction of NGCC, the proposed EGU GHG NSPS will standard

does is not impose any social costs (or generate monetized quantified net benefits) under

current and likely future market conditions.  

However, the net benefits from a policy interact withthis could be affected by the

relative generating costs, which in turn vary based on the prices of fuels like natural gas and

coal.  Because the impacts of this proposed rule depend on the cost of this standard is

estimated to be zero under EPA’s baseline scenario, and because the social costs are could be

expected to be especially sensitive to the relatively uncertain parameter of future natural gas

prices, which are uncertain, EPA conducted an illustrative analysis of the impacts of the rule

over a wide range of natural gas prices. an illustrative analysis of the breakpoints where natural

gas prices change the sign of the social costs of the policy (holding all other parameters

constant).52  This analysis describes considers two distinct thresholds in the price of natural gas

                                                      

51 The presence of net benefits for a given regulatory option is a necessary but not a sufficient condition for

optimal regulatory design. It does however; signify that the regulatory option is welfare improving for society. 52 In reality this is unlikely to be the case.  For example, high economic growth would increase both natural gas and

coal prices at the same time ‐ making it harder to alter the underlying cost advantage of NGCC generation.
5‐39

at present: one price at which the private cost of a representative new coal unit falls below that

of a representative NGCC unit, but the generation cost advantage remains outweighed by the

environmental damages from the perspective of society as a whole; and an even higher price at

which the environmental damages no longer outweigh the private cost advantage.  This

analysis presents three relevant ranges within the conditional distribution of future natural gas

prices that can be classified as a range of likely gas prices, unexpectedly high natural gas prices,

and unprecedented natural gas prices.  It is important to note that this illustrative analysis

considers variation in the natural gas price holding all else constant; as discussed above, an

ideal analysis would vary other conditions simultaneously.53  the pattern in social costs as

natural gas prices rise across three ranges: projected gas prices, unexpectedly high natural gas

prices, and unprecedented natural gas prices. In general, this analysis shows that the policy

would likely have a net benefit even under scenarios with much higher gas prices.  Under some

conditions, higher natural gas prices result in a net cost, holding all other parameters constant

and disregarding benefits that we are unable to monetize.54 However, it is important to note

that this analysis is limited in the types of social benefits and costs considered, given that it

does address the life‐cycle pollution associated with fossil fuels along with the limitations of

current SCC estimates, as previously discussed.

Likely Projected Natural Gas Prices. As described earlier in this chapter, the base case

modeling that EPA performed for this rule (as well as base case modeling that EPA has

performed for other recent air rules) indicates that new fossil fuel‐fired generating capacity

projected to be built through 2020 will be either natural gas‐fired combined cycle generation or

coal‐fired generation with CCS (the latter is assumed to be built with support from federal

grants).  This conclusion also holds for the high‐demand and low‐shale‐gas sensitivity analyses

considered above.  As shown earlier in the illustrative analysis, it is only when gas prices reach

approximately $9.60/mmBtu, that new conventional coal‐fired generation without CCS

becomes competitive with NGCC in terms of the levelized cost of electricity (in dollars per

megawatt hour) wholesale cost of electricity generation.

Projections of future market conditions suggest that it is likely that natural gas prices

will remain below this level.  As noted earlier in this chapter, EIA’s projected natural gas price

for 2020 in its reference scenario for AEO 2011 is $5.30 (in 2007 dollars).  For context, eEven

EIA’s most pessimistic gas sensitivity case (“low shale gas recovery per well”) only projects an

                                                      

53 For example, high economic growth would raise both natural gas and coal prices at the same time – extending

the range of natural gas prices for which NGCC retained a cost advantage. 54 In reality this is unlikely to be the case.  For example, high economic growth would increase both natural gas and

coal prices at the same time ‐ making it harder to alter the underlying cost advantage of NGCC generation.
5‐40

electricity sector gas price of $7.016.79/mmBTU (in 2007 dollars) in 2020 (the “low shale gas

recovery per play” scenario projects a price of $6.135.93/mmBtu in 2007 dollars in 2020).  In

other words, even under pessimistic natural gas sensitivity cases, NGCC is likely to remain the

economic choice for generation over the next two decades even in the absence of this

standard.  As a resultIn this scenario, it appears very likely that the social costs – and benefits –

of the proposed standard are expected towill be zero.

Unexpectedly High Natural Gas Prices.  In this illustrative analysis, at natural gas prices

above approximately $9.60/mmBtu, the private levelized cost of electricity for a representative

new conventional coal unit falls below that of a new NGCC unit.  Therefore, above that price

level some new conventional coal units might be constructed in the absence of the standard,

provided there is sufficient demand and new coal without CCS is competitive with other

generating technologies.55  However, these coal units would also impose additional

environmental and health damages in the form of global warming pollution and particulate

matter (as a result of SOx and NOx emissions) – an element of social costs that are avoided by

building an NGCC unit instead.  gas prices above $9.60/mmBTU, coal generation without CCS

becomes competitive with NGCC, which may mean that some new non‐CCS coal units might be

constructed in the absence of the standard provided there is sufficient demand, and new coal

without CCS is competitive with other generating technologies, and the relatively high price of

natural gas is expected to be sustained.  However, these coal units would also impose social

external costs in the form of global warming pollution and particulate matter (as a result of SO2

and NOx emissions) and this proposed standard would avoid those social costs.  

For a range of natural gas prices above $9.60/mmBtu, the resulting external costs will

outweigh the difference in the private costs in this illustrative example – indicating that the

proposed standard would yield net benefits.  For example, at gas prices of $10/MMBTU, the

illustrative non‐CCSconventional coal unit would generate power for $3/MWh less than an

NGCC unit56, but result in greater pollution damages of $916‐5070/MWh (see table 5‐76).57  

Under the proposed standard, if in this example the investor built the NGCC unit were built

instead, the resulting net social benefit would be $613 to 4767/MWh.  

                                                      

55 See section 5.4 for a discussion of how local conditions and other factors influencing the levelized cost

comparison may influence the natural gas price where the levelized cost of the conventional coal unit and the

NGCC unit are the same. 56 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBTU increase in natural gas

prices.   57 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See

previous footnote.
5‐41

For context, we note that these circumstances are far less likely than the zero cost

scenario outlined above.  To put this gas price breakpoint point into historical context,

$9.60/MMBTU is higher than any average annual gas price (in 2007 dollars) observed over the

last 10 years, and it has only been reached temporarily in 9 8 of the last 120 months.58,59  

Looking forward, the continued development of unconventional natural gas resources in the

U.S. suggests that gas prices would actually tend to be towards the lower end of the historical

range.  As discussed above, none of the EIA sensitivity cases (which represent future price

trajectories for both gas and coal) show scenarios where non‐compliant coal becomes more

economic than NGCC before 2020.

Unprecedented Natural Gas Prices.  At extremely high natural gas prices, the private

generating costs of non‐compliant coal are significantlywould be sufficiently lower than the cost

of new natural gas thatand the net social cost benefit of the standard could be positive negative

(negative i.e., net benefits) under some assumptions for environmental damage costs. For

example, at gas prices of $15/MMBTU, the illustrative non‐CCSconventional coal unit would

generate power for roughly $376/MWh less than an NGCC unit but result in social costs of

$916‐5070/MWh (see table 5‐67).  Under the proposed standard, if ana NGCC unit were built

instead generator would likely build the NGCC unit instead, the resulting in a net social benefit

of would range from $‐28219 to 1334/MWh.  The point at which this standard would result in

net social costs depends heavily upon the value for damages from GHGs and SO2. For example,;

assuming an SCC using a 3% discount rate, along with a 7% discount rate for estimating benefits

from reduced SO2 and the mortality‐risk estimate from Pope (2002), natural gas prices above

$12/mmBtu in this illustrative example would result in net social costs from the proposed

standard.  Alternatively, using an SCC value of 3% and using the mortality‐risk estimate from

Laden (2006) along with a 3% discount rate for PM benefits, the corresponding threshold for

natural gas prices would be $14/mmBtu.    Natural gas prices above these levels would be

unprecedented.  Average annual natural gas prices delivered to the electricity sector have not

exceeded $ 9.38 /mmBtu (in 2007 dollars) over the last 15 years, and projected prices do not

                                                      

58 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices

to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural gas

prices to the electricity sector over the past 10 years (since 2001). 59 It is important to note that relatively high gases prices in a single month or year will not drive the investment

decision in the technology employed for new generating units.  Instead that decision will be motivated by

expectations of relative fuel prices over the lifetime of the unit.  Therefore given the historical path of natural

gas prices and the forecasts for the future, it is highly unlikely that expectations of sustained high natural gas

prices, to the degree necessary to drive technology choices, will be realized.
5‐42

begin to approach this level in any of EIA’s scenarios.60,61  As a result, based on historical gas

prices as well as projections, EPA believes that there is an extremely small probability that

natural gas prices will reach (let alone remain at) levels at which this standard would generate

net social costs. in this illustrative example would generate net social costs at average gas

prices of $13 to $18/MMBTU.  Annual natural gas prices delivered to the electricity sector have

not exceeded $ 9.26 /MMBTU over the last 15 years.  

We emphasize that differences in generating costs, plant design, local factors, and the

relative differences between fuels costs can all have major impacts on the precise

circumstances where under which this standard would be projected to have no costs, net

benefits or net costs.  However, based on average annual gas prices over the last 15 years, we

project that this standard is most likely to have no notablenegligible costs, that and, if it does

imposes costs, there is some small probability that it likely also produces positive, although

modest, quantifiable net benefits. There is, and an exceedingly low probability that it results in

net costs.

5.10.3 Illustrative Costs and Benefits of CCS Compared with Conventional Coal  

The analysis above focuses on two well developed control technologies, conventional

supercriticitcal coal and natural gas combined cycle.   Because these technologies are well

developed, there is significantly more certainty about operating costs than for new, emerging

technologies like coal with CCS.  As a result, any analysis which that examines the relative social

costs of coal vs. coal with CCS is considerably more uncertain and should primarily be used as a

guide to the key sensitivities in the relative social costs.  EPA compared the costs and damages

for a model pulverized coal (PC) EGU using supercritical steam conditions (like the one used in

the comparisons above) to and IGCC plant with a CCS system (e.g. Selexol). See technical memo

“Control Cost and Environmental Impacts of the Proposed GHG NSPS on new Coal‐Fired Electric

Utility Generating Units” for more details. [SEE TECHNICAL MEMO FOR DETAILS].

EPA analyzed the cost and emission impacts for two scenarios. In the first scenario,

partial capture achieves the proposed emissions rate of 1,000 lb CO2/MWh gross output. This

requires that approximately 391% of the CO2 is captured and stored.  EPA has not previously

                                                      

60 http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm . EIA reports average annual delivered natural gas

prices to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural

gas prices to the electricity sector over the past 10 years (since 2001). 61 Note that while EIA forecasts natural gas prices to rise, it also forecasts coal price to rise as well. An ideal

comparison of levelized costs in future time periods should account for the expected change in both natural gas

and coal prices.
5‐43

developed costs for such a unit, therefore, this analysis may not fully realize all of the cost

savings possible from building a unit with significantly less than 90% capture (for instance, an

IGCC could be built with a conventional gas turbine, rather than one designed for higher

temperature characteristics of a higher hydrogen content fuel). A 90% capture system was also

examined to analyze the cost of several proposed new coal‐fired EGUs using CCS. In the near

term, any new coal‐fired EGU with CCS would mostly likely be located in areas amenable to

using the captured CO2 in enhanced oil recovery (EOR) operations. This is because EOR provides

a revenue stream that is not available for other forms of geologic storage. For example, the

Texas Clean Energy project62 is planning to capture 90% of the CO2 and sell it for enhanced oil

recovery.  

To evaluate the potential revenues from EOR we examined two options.  We considered

a case where CO2 could be sold for $45/ton based on recent DOE studies for the 90% capture

case.

63  We also considered a lower revenue sensitivity where CO2 could be sold for $15/ton

(equivalent to the cost assumed for the transport and storage of CO2 in the analysis) for the

partial capture case. Costs for the IGCC unit with 90% capture and the ultra‐supercritical

pulverized coal‐fired (SPC) unit without CCS were derived from IPM version 4.10.64 These cost

estimates are generally consistent with the range of studies estimating the cost of CCS that are

available, however there is uncertainty around any such projections of technology costs,

particularly for early movers of this technology. Capital costs for the IGCC unit with 39% capture

were assumed to be 90% of the capital costs for an IGCC unit with 90% CCS.Costs for the IGCC

unit with 30% capture were derived from the costs for the IGCC unit with 90% CCS using best

engineering judgment. EPA estimated the benefits associated with avoided CO2 and SO2

emissions in a similar fashion to the one described above. See technical memo “Control Cost

and Environmental Impacts of the Proposed GHG NSPS on new Coal‐Fired Electric Utility

Generating Units” for more details. [REFERENCE TECHNICAL MEMO IN THE DOCKET]

Table 5‐87. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional

Coal Plant (Millions 2007$) – NOTE – WILL BE REVISED TO $/MWh FOR

CONSISTENCY

USPC to IGCC with USPCS to IGCC with

                                                      

62 http://www.texascleanenergyproject.com/ 63 US DOE / NETL studies have assumed a delivered CO2 price ranging from $40 ‐ $45/tonne.  “Improving Domestic

Energy Security and Lowering CO2 Emissions with “Next Generation” CO2‐Enhanced Oil Recovery (CO2‐EOR)”,

DOE/NETL‐2011/1504 (June 2011); and “Storing CO2 with Enhanced Oil Recovery, DOE/NETL‐402/1312

(February 2008). 64http://www.epa.gov/airmarkets/progsregs/epa‐ipm/BaseCasev410.html
5‐44

390% Capture 90% Capture

Additional Gross Annual Private Costs $1780.0 $34130.3

Revenue from EOR $517.4 (@$15/ton) $37143.7 (@$45/ton)

Net Additional Annual Private Costs $1262.6 ($313.4)

Value of Quantified Monetized Benefits

      SCC 3% with Pope 7% $1358 $24109

      SCC 3% with Laden 3% $23101 $34151

Net Monetized Benefits

      SCC 3% with Pope 7% ($14.6) $27122.4

      SCC 3% with Laden 3% $1138.4 $37164.4

This analysis suggests that the relative social cost of CCS compared to conventional coal

is sensitive to the achieved generating costs for CCS units, the revenue stream from EOR, and

the monetary value of avoided climate and other air pollution damages.  However, it also

suggests that, at relatively low prices for EOR revenue ($15/MWh), CCS generation can

generate net social benefits compared to conventional coal generation. As before, it is

important to note that these comparisons omit additional benefits that may be associated with

the abatement of greenhouse gas emissions.

EPA recognizes that this illustrative analysis is somewhat novel, and requests comment

on ways to incorporate uncertainty about future economic factors (and gas prices in particular)

into the consideration of the social cost of this rule.

5.113   Macroeconomic and Employment Impacts

This proposed EGU GHG NSPS is not anticipated to change GHG emissions for newly

constructed electric generating units, and nor is it anticipated to impose notable negligible

costs or, quantified benefits., or have notable economic or employment impacts.  EPA typically

presents the economic impacts to secondary markets (e.g., changes in industrial markets

resulting from changes in electricity prices) and impacts to employment or labor markets

associated with proposed rules based on the estimated compliance costs and other energy

impacts, which serve as an input to such analyses.  However, since the EPA does not forecast a

change in behavior relative to the baseline in response to this proposed rule, there are no

notable macroeconomic or employment impacts expected as a result of this proposed rule.   
5‐45

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